Much attention has been given to the simulation of naturally fractured reservoirs in the recent literature. The most prevalent approach is a dual-porosity (or dual-porosity/dual-permeability) formulation with computation blocks that may represent several individual matrix blocks. In models of this type, the processes of gas/oil drainage and water/oil imbibition have caused particular difficulties. Some authors have attempted to represent the correct behavior through a gravity term that assumes a simplified fluid distribution in the matrix. Others have used pseudo-capillary-pressure functions for the matrix, the fracture, or both. These functions also assume a simplified matrix fluid distribution or are obtained by "history matching" with a fine-grid model of a single matrix block. Still others have introduced refinement of the matrix into multiple blocks.In this paper, the authors examine the mechanisms involved in gas/oil drainage and water/oil imbibition and propose a simple way to represent that behavior in a dual-porosity simulator. Basically, the formulation uses pseudo-capillary-pressure curves for both the matrix and fracture. The fracture curve can be determined directly from rock properties and matrix-block dimensions, while the matrix curve can be obtained from the results of a single simulation of a fine-grid model of a single matrix block. The approach is less costly than matrix subdomain and history-matching alternatives and is often more accurate than solutions that rely on a simplified gravity term.

Research Co. q Now associated withLawrenceLwermoreLaboratory. SPE Members Copyng..! ""'-+7. Society ofPetroleum Engineers Thispaperwas prepared lot ptesentahon a![heMnlh SPESpmos,um onRmewojr slmulallon held InsanAnton:o. Texas Febru.m 1-4.1987 Th,apaperwas selected for presentabon IYan SPE Program Com~mee f0110w,n9 fevtew oftnfOrmatlon conlalned m an abstfacl aubmstted bythe author(s) Contents ofthepapel. aspresented. havenotbeenfewewedbytheSwe!y 01Petroleum Engineers and aresubject tocorrachon bythe author(s) Thmmeterlal. aspresented. doesnolnecessallly fef Iecl anyWa$tton O!thes~lelyofpe!(oleum EnQ'neers. Its Ofrlcers. ormembers 'apers presente9 alSPE mc hngaaresubjecl 10pubhcahon f. 'wewby EditorSal cOmmrtleeS 01IheSOCrety otpetrOkumEngmeeraPermms,on toCOPYIS WJtjCled 109n absllact ofnetmore!han3NIwofda Hluslral,ons may notbe cop,edThe abslracl should contain conspicuous acknowledgment of whefeandbywhom the papef IS presented Write Pubhcal!ons Manager, SPE,P O Box833836. Rchardson. 7X 75083-3836 Ta.ex. 730969 SPEDAL the flow/conservation steps used in the simulator. Results are presented to illustrate various cases. Phase equili'~rium calculations involv' the Q9A u * SPE 16024 G. SUBRAMANIAN et a; 5

Effective exploitation of the thin oil rim in the Amherstia / Immortelle 22 sand is particularly challenging because of the size of the overlaying gas cap, 2TCF, and the thickness of the oil rim varying between 31 to 46 feet gross pay interval. Since oil wells in the thin oil rim of the 22 sand did not justify well cost, the challenge, then, was to make the oil wells more attractive to facilitate early depletion of the oil rim. Reservoir simulation work was undertaken and a joint team was formed to evaluate the reservoir performance and determine the best strategy for depletion. This team consisted of subsurface professionals from the Amherstia and Immortelle fields, and the bp Houston technology group. The performance of the two wells in the reservoir was history-matched and then the model was used to develop an improved strategy. The reservoir simulation grid used was aligned with the major fault patterns and nested local grid refinement was utilized to better understand depletion of the oil rim. Sensitivity analysis conducted demonstrated that locating longer horizontal oil wells with larger size tubing in the upper third of the oil rim proved to be the best strategy for depletion of the oil rim. The strategy provided higher production rates with earlier accessibility to gas reserves while outrunning the aquifer. Introduction Located 30 to 40 miles off the south - east cost of Trinidad in 235 feet of water (Figure 1), the Immortelle/ Amherstia field complex consists of a number of stacked reservoirs, the largest of which is the 22 sand. This field complex consists of two major NE plunging anticlines; the Immortelle platform lies on the northern-most anticline while the Amherstia platform is perched on the southern-most anticline. A number of faults intersect these two anticlines. The largest of these is the A4 fault. The reservoir consists of a coarsening upward clastic sequence interpreted to be a shore face or delta front environment. Some of the deeper reservoirs, inclusive of the 22 sand, are continuous across the Amherstia / Immortelle field complex.